Marine riser technology and its development have been driven by two basic needs in the oil industry.
The first need has been to resolve the challenges that are related to using drilling risers during exploratory drilling. These risers bridge between the seabed and the surface when doing exploration drilling from a floating vessel, which is normally either a semi-submersible drilling rig, or a drill ship. These riser needs can be characterized as large diameter and relatively low pressure. They are designed for rapid disconnect from the seabed equipment, efficient running and retrieval via the drilling vessel, and relatively short design life. Basic floating drilling methods were established in the 1960's1 (superscripts refer to “List of References” appearing before the Claims at the end of this specification) and these methods continue to be improved upon today2.
The second riser need occurs when exploration drilling is successful, leading to a field development. These field development risers bridge between the life-of-field development seabed and surface Host Facility. These risers have small diameters and large diameters, operate at relatively high pressures, and are designed in accordance with field development expectations for near-continuous hydrocarbon depletion that may require 20 years and more of uninterrupted service. These risers may include export and import riser systems that are related to the hydrocarbon production and sales. Also, if well drilling and completion is to be performed from the Host Facility, these riser needs have also to be addressed3.
The pace for deepwater developments in the Gulf of Mexico has been dramatic since the mid-1990's. A brief summary is presented in Appendix IV. The Industry has gone through a series of stages of riser technology development, resulting in the present preferred Steel Catenary Riser (SCR)/Flowline (FL) riser solutions for deepwater. SCR's have evolved in a natural way to replace the large, complex and costly top tensioning equipment that are required when vertical riser systems are used. Vertical risers with top tensioning are effective to water depths of about 4000 feet. However, top tensioning equipment, because of its size, weight, and tight clearances, is costly and difficult to manage. This geometric relationship becomes increasingly challenging when the Host Facility must support this equipment for riser strokes of more than 7–12 feet. For one project in the Gulf of Mexico in 6000 feet of water, riser top motions can approach about 20 feet. These motions represent major design challenge, even for the SCR/FL risers. The challenge is magnified due to the large number of risers that must bridge between the seabed and the Host Facility.
This stroke length is necessary to accommodate the change in riser system length as the Host Facility moves from its neutral position. Without this riser stroke, the riser would be subjected to either over-stressing or large stress level cycles. Riser failure can be manifested by either overstressing it, or by subjecting it to excessive stress cycling. The stress cycling can lead to riser failure due to accumulated fatigue damage, even though the allowable stress is not exceeded for the riser system.
The riser stroke length challenge is graphically represented in FIG. E-2 of a U.S. provisional patent application filed on Apr. 26, 2002 under Ser. No. 60/375,619. When a riser is attached to a fixed point on the seabed and directly to the Host Facility, the riser top must move along with the Host Facility. Considering the life of field possibilities, the range of motions that may occur is extensive. The solution to this changing riser length (stroke requirement) should be robust, as failure to do so is can lead to riser failure. Riser failure can be caused either by the immediate effect of over-stressing, or by diminished fatigue life due to excessive stress cycling. Riser failure due to collapse can also occur, but this tends to be a direct consequence of over-stressing it. In the case of Host Facilities that have very large motions, such as the FPSO systems that have been used outside the Gulf of Mexico, the riser stroke requirement can be met by using flexible pipe16.
A flexible pipe solution (See FIG. E-3(a) of the U.S. provisional patent application filed on Apr. 26, 2002 under Ser. No. 60/375,619), has been used successfully many times. However, for very deep water, this method can be costly. Also, flexible pipe technology for risers (i.e., ones that require a design combination of deepwater, high pressure, high temperature, or large size) remains under on-going development before flexible pipe will be ready for the long field life riser applications. Flexible pipe risers can provide good closing solutions when used in conjunction with a free-standing rigid riser (See FIG. E-3(b) of the U.S. provisional patent application filed on Apr. 26, 2002 under Ser. No. 60/375,619). This arrangement is sometimes referred to as a “hybrid riser” because it combines elements of both buoyancy for top tensioning of the steel risers and flexible pipe to complete the bridging from the top of the rigid risers to the Host Facility. This arrangement is commonly used for Spar well system jumpers that bridge between the well tree and the host manifold. The flexible pipe elements are comprised of a wall body that is made up of various combinations of metal and elastomers. The flexible pipe design is tailored to meet each specific application need. Although the resulting flexibility can help resolve the strokelength challenges that exist with rigid risers and they provide an efficient closing duty, their use for a life-of-field application for the entire riser system remains uncertain. Also, specialized installation methods are often used to ensure that the integrity of flexible pipe is maintained.
The fundamental need for a top-tensioning assembly is represented in FIG. E-4A of the U.S. provisional patent application filed on Apr. 26, 2002 under Ser. No. 60/375,619). In that example, no top-tensioning assembly with stroke length change is provided for the riser. Thus, it bridges directly between the seabed connection point and a point on the host facility. This is only shown as a hypothetical configuration. It assumes that the Host Facility could be designed such a way that the combination of hull and mooring would limit the hull motions so that this would be feasible. Also, it assumes that no over pull is applied to the riser at the neutral position. In an actual design, some over pull is necessary to ensure riser integrity for the range of environmental loads to which it will be subjected. However, as can be seen in this drawing, as the Host Facility moves laterally from its neutral position, the riser top-tensile stress begins to increase rapidly. In this example, an allowable material stress value of about 60,000 psi was assumed. Modern steels can be manufactured to provide material properties like this, including the direct requirement for suitable welding methods. Work to provide suitable commercial grade steels of higher stress values is continuing. But if it were possible to keep the Host Facility offset to within a very small percent of water depth, this type of rigid riser could be feasible today if cost realities related to the hull and mooring were not a consideration.
Given the recent pace of these developments, it is easy to understand why a deepwater field development would be based on the most proven riser systems that are available to the system designers. However, when subsea wells and equipment are located directly under the Host Facility, managing the seabed equipment, wells flowlines, and risers is costly and complex. The SCR/Flowline system requires that the SCR be routed in a straight line and away from the Host Facility. The flowline is routed around and back under the Host Facility, where it can then be connected to the subsea manifold using a jumper. Also, a flowline jumper arrangement is required to allow efficient transition between the SCR and the flowline. The drilling riser that is located on the Host Facility can be equipped with a conventional riser top-tensioning system. This is possible because it can be disconnected when Host Facility motions exceed a pre-determined limit. Since the production export and import risers cannot be disconnected this way, the use of a top tensioning assembly at the surface for these risers can only be obtained at the expense of space, weight, and clearance requirements on the topsides. The complexity and cost of doing this is high for deepwater applications. This is the fundamental reason why the SCR/Flowline method has been used. It represents a better solution than can be achieved by using a vertical riser with a top tensioning assembly. Top-tensioned risers continue to meet field development needs, and it is expected that they will continue to do so for many situations. Even so, the need for new approaches continues. Current riser design practices15 recognize this need, and theses practices provide guidance on the approaches that can be used to qualify new riser designs.
In those cases that require vertical access into the riser system, a top tensioning assembly may continue to be a preferred solution, as this may be the only practical means for providing vertical riser access for well drilling and completion purposes. However, some types of risers do not require vertical access. These riser systems include the export and import risers that are used to move products away from and onto the Host Facility. The SCR/FL solution can also be used to meet these duties, especially for the larger riser sizes.
These problems have existed for some time. Considerable effort has been made, and significant amounts of money have been expended to resolve this problem. In spite of this, the problem still exists. Actually, the problem has become aggravated with the passage of time because the water depth requirements continue to rely on costly solutions, or solutions that are approaching their limits of practical application.